This invention relates to a process for the separation of a gas containing hydrocarbons.
Ethylene, ethane, propylene, propane and heavier hydrocarbons can be recovered from a variety of gases, such as natural gas, refinery gas, and synthetic gas streams obtained from other hydrocarbon materials such as coal, crude oil, naphtha, oil shale, tar sands, and lignite. Natural gas usually has a major proportion of methane and ethane, i.e., methane and ethane together comprise at least 50 mole percent of the gas. The gas may also contain relatively lesser amounts of heavier hydrocarbons such as propane, butanes, pentanes and the like, as well as hydrogen, nitrogen, carbon dioxide and other gases.
The present invention is generally concerned with the recovery of ethylene, ethane, propylene, propane and heavier hydrocarbons from such gas streams. A typical analysis of a gas stream to be processed in accordance with this invention would be, in approximate mole percent, 92.5% methane, 4.2% ethane and other C.sub.2 components, 1.3% propane and other C.sub.3 components, 0.4% iso-butane, 0.3% normal butane, 0.5% pentanes plus, with the balance made up of nitrogen and carbon dioxide. Sulfur containing gases are also sometimes present.
The historically cyclic fluctuations in the prices of both natural gas and its natural gas liquid (NGL) constituents have reduced the incremental value of ethane and heavier components as liquid products. This has resulted in a demand for processes that can provide more efficient recoveries of these products. Available processes for separating these materials include those based upon cooling and refrigeration of gas, oil absorption, and refrigerated oil absorption. Additionally, cryogenic processes have become popular because of the availability of economical equipment that produces power while simultaneously expanding and extracting heat from the gas being processed. Depending upon the pressure of the gas source, the richness (ethane and heavier hydrocarbons content) of the gas, and the desired end products, each of these processes or a combination thereof may be employed.
The cryogenic expansion process is now generally preferred for ethane recovery because it provides maximum simplicity with ease of start up, operating flexibility, good efficiency, safety, and good reliability. U.S. Pat. Nos. 4,157,904, 4,171,964, 4,278,457, 4,687,499, 4,854,955, 4,869,740, and 4,889,545 describe relevant processes.
In a typical cryogenic expansion recovery process, a feed gas stream under pressure is cooled by heat exchange with other streams of the process and/or external sources of refrigeration such as a propane compression-refrigeration system. As the gas is cooled, liquids may be condensed and collected in one or more separators as high-pressure liquids containing some of the desired C.sub.2 + components. Depending on the richness of the gas and the amount of liquid formed, the high-pressure liquids may be expanded to a lower pressure and fractionated. The vaporization occurring during expansion of the liquid results in further cooling of the stream. Under some conditions, pre-cooling the high pressure liquid prior to the expansion may be desirable in order to further lower the temperature resulting from the expansion. The expanded stream, comprising a mixture of liquid and vapor, is fractionated in a distillation (demethanizer) column. In the column, the expansion cooled stream(s) is (are) distilled to separate residual methane, nitrogen, and other volatile gases as overhead vapor from the desired C.sub.2 components, C.sub.3 components, and heavier components as bottom liquid product.
If the feed gas is not totally condensed (typically it is not), the vapor remaining from the partial condensation can be split into two or more streams. One portion of the vapor is passed through a work expansion machine or engine, or an expansion valve, to a lower pressure at which additional liquids are condensed as a result of further cooling of the stream. The pressure after expansion is essentially the same as the pressure at which the distillation column is operated. The combined vapor-liquid phases resulting from the expansion are supplied as feed to the column.
The remaining portion of the vapor is cooled to substantial condensation by heat exchange with other process streams, e.g., the cold fractionation tower overhead. Depending on the amount of high-pressure liquid available, some or all of the high-pressure liquid may be combined with this vapor portion prior to cooling. The resulting cooled stream is then expanded through an appropriate expansion device, such as an expansion valve, to the pressure at which the demethanizer is operated. During expansion, a portion of the liquid will vaporize, resulting in cooling of the total stream. The flash expanded stream is then supplied as top feed to the demethanizer. Typically, the vapor portion of the expanded stream and the demethanizer overhead vapor combine in an upper separator section in the fractionation tower as residual methane product gas. Alternatively, the cooled and expanded stream may be supplied to a separator to provide vapor and liquid streams. The vapor is combined with the tower overhead and the liquid is supplied to the column as a top column feed.
In the ideal operation of such a separation process, the residue gas leaving the process will contain substantially all of the methane in the feed gas with essentially none of the heavier hydrocarbon components and the bottoms fraction leaving the demethanizer will contain substantially all of the heavier components with essentially no methane or more volatile components. In practice, however, this ideal situation is not obtained for the reason that the conventional demethanizer is operated largely as a stripping column. The methane product of the process, therefore, typically comprises vapors leaving the top fractionation stage of the column, together with vapors not subjected to any rectification step. Considerable losses of C.sub.2 components occur because the top liquid feed contains substantial quantities of C.sub.2 components and heavier components, resulting in corresponding equilibrium quantities of C.sub.2 components and heavier components in the vapors leaving the top fractionation stage of the demethanizer. The loss of these desirable components could be significantly reduced if the rising vapors could be brought into contact with a significant quantity of liquid (reflux), containing very little C.sub.2 components and heavier components; that is, reflux capable of absorbing the C.sub.2 components and heavier components from the vapors. The present invention provides the means for achieving this objective and significantly improving the recovery of the desired products.
In accordance with the present invention, it has been found that C.sub.2 recoveries in excess of 96 percent can be obtained. Similarly, in those instances where recovery of C.sub.2 components is not desired, C.sub.3 recoveries in excess of 98% can be maintained. In addition, the present invention makes possible essentially 100 percent separation of methane (or C.sub.2 components) and lighter components from the C.sub.2 components (or C.sub.3 components) and heavier components at reduced energy requirements. The present invention, although applicable at lower pressures and warmer temperatures, is particularly advantageous when processing feed gases in the range of 600 to 1000 psia or higher under conditions requiring column overhead temperatures of -110.degree. F. or colder.
For a better understanding of the present invention, reference is made to the following examples and drawings. Referring to the drawings:
FIG. 1 is a flow diagram of a cryogenic expansion natural gas processing plant of the prior art according to U.S. Pat. No. 4,157,904;
FIG. 2 is a flow diagram of a cryogenic expansion natural gas processing plant of an alternative prior art system according to U.S. Pat. No. 4,687,499;
FIG. 3 is a flow diagram of a cryogenic expansion natural gas processing plant of an alternative prior art system according to U.S. Pat. No. 4,889,545;
FIG. 4 is a flow diagram of a natural gas processing plant in accordance with the present invention;
FIGS. 5 and 6 are flow diagrams illustrating alternative means of application of the present invention to a natural gas stream;
FIG. 7 is a fragmentary flow diagram showing a natural gas processing plant in accordance with the present invention for a richer gas stream;
FIG. 8 is a fragmentary flow diagram illustrating an alternative means of application of the present invention to a natural gas stream from which recovery of propane and heavier hydrocarbons is desired; and
FIGS. 9 and 10 are fragmentary flow diagrams illustrating alternative means of application of the present invention to a natural gas stream.
In the following explanation of the above figures, tables are provided summarizing flow rates calculated for representative process conditions. In the tables appearing herein, the values for flow rates (in pound moles per hour) have been rounded to the nearest whole number for convenience. The total stream rates shown in the tables include all nonhydrocarbon components and hence are generally larger than the sum of the stream flow rates for the hydrocarbon components. Temperatures indicated are approximate values rounded to the nearest degree. It should also be noted that the process design calculations performed for the purpose of comparing the processes depicted in the figures are based on the assumption of no heat leak from (or to) the surroundings to (or from) the process. The quality of commercially available insulating materials makes this a very reasonable assumption and on that is typically made by those skilled in the art.